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B p   petrophysical reservoir evaluation B p petrophysical reservoir evaluation Document Transcript

  • RHUM FIELD RHUM PETROPHYSICAL RESERVOIR EVALUATION Simon Kay July 2002 BP Exploration Operating Company Limited Dyce, Aberdeen E:BACK UPSCANPetrophysicsRhum Petrophysical Reservoir Evaluation .doc MNS Developments v1.0 13/08/2005
  • RHUM FIELD RHUM PETROPHYSICAL RESERVOIR EVALUATION SIMON KAY July 2002 BP Exploration Operating Company Limited Dyce, Aberdeen E:BACK UPSCANPetrophysicsRhum Petrophysical Reservoir Evaluation .doc MNS Developments v1.0 13/08/2005
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 TABLE OF CONTENTS List of Figures List of Tables List of Enclosures 1. EXECUTIVE SUMMARY............................................................................................................... 4 2. INTRODUCTION AND SCOPE..................................................................................................... 7 2.1. 2.2. Workscope ........................................................................................................................ 7 Depth Conventions............................................................................................................ 8 3. FIELD AND WELL DATABASE..................................................................................................... 9 4. FIELD TEMPERATURE AND PRESSURE ................................................................................ 11 5. WELL – BY – WELL EVALUATION ............................................................................................ 13 5.1. 5.2. 6. 3/29a – 4 Review ............................................................................................................ 13 5.1.1. 3/29a – 4 Data .................................................................................................. 13 5.1.2. Review of PGL Analysis.................................................................................... 14 5.1.2.1. Environmental Corrections ..................................................................... 14 5.1.2.2. Shale Volume (VSH) .............................................................................. 15 5.1.2.3. Effective Porosity (PHIE) ........................................................................ 15 5.1.2.4. Water Saturation (SW) ........................................................................... 15 5.1.3. MRIL Processing............................................................................................... 15 5.1.4. New Petrophysical Analysis.............................................................................. 16 5.1.4.1. Environmental Corrections ..................................................................... 16 5.1.4.2. Analysis .................................................................................................. 16 5.1.4.3. VSH ........................................................................................................ 16 5.1.4.4. PHIE ....................................................................................................... 18 5.1.4.5. SW .......................................................................................................... 20 3/29a – 2 Review ............................................................................................................ 21 5.2.1. New Petrophysical Analysis.............................................................................. 21 5.2.1.1. VSH ........................................................................................................ 21 5.2.1.2. PHIE ....................................................................................................... 21 5.2.1.3. SWE........................................................................................................ 21 5.2.1.4. Lower Reservoir Section ........................................................................ 21 LITHOLOGY ANALYSIS ............................................................................................................. 23 6.1. 6.2. Methodology.................................................................................................................... 23 Validation......................................................................................................................... 25 7. PERMEABILITY ANALYSIS........................................................................................................ 27 8. PRESSURE ANALYSIS AND FREE WATER LEVEL ................................................................ 31 9. SATURATION-HEIGHT FUNCTIONS ........................................................................................ 35 10. ZONE AVERAGES ......................................................................................................... 37 11. RHUM ROCK PROPERTIES.......................................................................................... 38 12. CONCLUSIONS AND RECOMMENDATIONS............................................................... 39 13. REFERENCES................................................................................................................ 40 Page 1
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 List of Figures Figure 1.1. Figure 1.2. Figure 2.1. Figure 4.1. Figure 4.2. Figure 5.1. Figure 5.2. Figure 6.1. Figure 6.2. Figure 6.3. Figure 6.4. Figure 6.5. Figure 6.6. Figure 6.7. Figure 7.1. Figure 7.2. Figure 7.3. Figure 8.1. Figure 8.2. Figure 8.3. Figure 9.1. 3/29 – 2 Rhum Well Summary – Reservoir Section ................................................ 5 3/29a – 4 Rhum Well Summary – Reservoir Section .............................................. 6 Rhum Field Location Map.......................................................................................... 8 3/29a – 4: Temperature Gradient used in Log Analysis ....................................... 11 Rhum Field Formation Pressures........................................................................... 12 GR Response Histograms ....................................................................................... 17 3/29a – 4 Core Porosity vs Log Density Crossplot in the Gas Leg ..................... 19 GR vs Depth Plot: 3/29 – 2 & 3/29a – 4. .................................................................. 24 RHOB vs Depth Plot: 3/29 – 2 & 3/29a – 4.............................................................. 24 Crossplot – RHO_MAA vs U_MAA: 3/29a – 4 Reservoir ...................................... 24 Crossplot – PHIT vs RHO_MAA: 3/29 – 2 and 3/29a – 4 Reservoir...................... 24 RHOB Histogram: 3/29 – 2 & 3/29a – 4. .................................................................. 25 RHO_MAA vs VSH Cross Plot: 3/29 – 2 & 3/29a – 4.............................................. 25 3/29a – 4 UMR2 Zone Log Resolution .................................................................... 26 3/29 – 2 Poroperm Relationship.............................................................................. 28 3/29a – 4 Poroperm Relationship............................................................................ 29 3/29a – 4 Log Permeability Compared with Core Permeability ........................... 30 3/29a – 4: RCI and FMT Formation Pressure Plot ................................................. 32 Rhum Field Formation Pressure Plot ..................................................................... 33 Well Corellation in True Vertical Depth Indicating FWL Position in Reservoir.. 34 3/29a – 4 Sw – Height Functions............................................................................. 36 List of Tables Table 3.1. Rhum Field Data............................................................................................................. 9 Table 3.2. Data Availability – Rhum Area Wells Loaded to Geolog .............................................. 10 Table 3.3. Rhum Sand Reservoir Zone Tops................................................................................ 10 Table 5.1. Well 3/29a – 4 Log Data Summary for Zones of Interest............................................. 13 Table 5.2. Well 3/29a – 4 Test Data.............................................................................................. 14 Table 5.3. CNC Log Environmental Correction Parameters ......................................................... 15 Table 5.4. Log Analysis Constants................................................................................................ 18 Table 5.5. 3/29a – 4 DST1B Water Analysis................................................................................. 20 Table 5.6. 3/29a – 4 RW from Core Brine Extracts....................................................................... 21 Table 6.1. Comparison of Core vs Log Defined Sands................................................................. 25 Table 8.1. Rhum Formation Pressure Data................................................................................... 31 Table 9.1. Saturation-Height Functions Derived from Air-brine Capillary Pressure Measurements. ........................................................................................................................................................ 35 Table 10.1. 3/29-2 Reservoir Properties ....................................................................................... 37 Table 10.2. 3/29a-4 Reservoir Properties ..................................................................................... 37 List of Enclosures 1. 3/29a –4 Detailed CPI, 1:500 2. 3/29a –4 Simplified CPI, 1:500 3. 3/29 – 2 CPI, 1:500 Page 2
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 APPENDICES A1. Geolog Database Structure A2. Core Data Listings A3. SCAL Results Page 3
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 1. EXECUTIVE SUMMARY The Rhum Field contains high pressure and high temperature (HPHT) dry gas in late Jurassic thinly-bedded turbidite sands. The sands are informally named as the Rhum Sand and belong to the J74 to J62 sequences. The field has only three well control points: 3/29 – 1, 3/29 – 2 and 3/29a – 4. 3/29 – 1 encountered sands below Cretaceous mudstones that are of inferred late Jurassic age but cannot be dated conclusively. The well took a gas kick, was not logged across the reservoir, and was terminated 3 metres into the sand. In 3/29 – 2 the entire 148-metre gross thickness Rhum Sand reservoir was gas-bearing. The well was not tested because suitable HPHT test equipment was not developed at the time of drilling (1977). Only two valid Repeat Formation Tester (RFT) pressure points were obtained. A single 14-metre core was cut in a thinly-interbedded sand interval. A basic gamma ray-density-resistivity-sonic log suite was obtained. Core indicated that the reservoir was a thinly-bedded turbidite sequence. 3/29a – 4, drilled in 2000, encountered 191 metres of gross Rhum reservoir, drilled through a gas-water contact, and was successfully tested. 93 metres of core were cut, out of 191 metres of reservoir (nearly half the entire reservoir sequence). In order to resolve and quantify reservoir quality in the thinly-bedded sequence, a comprehensive suite of log and pressure data was acquired. This report details log analysis incorporating special core analysis (SCAL) data from 3/29a – 4 and includes a re-analysis of 3/29 – 2. The selected logging program was largely successful in 3/29a – 4 and did improve thin sand definition. It is important to have a range of logging tools to address separate but related aspects of reservoir quality. Thus the best tool for determining gas saturation and sand volume overall was the Magnetic Resonance Imaging Log (MRIL); while individual thin bed quality was best measured by high-resolution density logs, and the 3D Explorer Induction Log (3DEX) tensor resistivity tool. It was difficult to get an accurate measure of water saturation from log and core data. Core saturation data in 3/29a – 4 indicated very low water saturations in the gas leg. Although the direct core saturation data agreed with the MRIL saturations, other indicators (log SW and capillary pressure data) suggest higher water saturations in the gas leg. Core saturation data should be reviewed. Special core analysis of 3/29a – 4 core provided refined Archie parameter values, porosity and permeability data corrected for reservoir pressure and overburden, confirmation of formation water resistivity and saturation-height data. Very thin, cm-scale, sand beds were seen in core that are not detectable on logs but are likely to contribute to production. Reliable pressure data were obtained that define gas and water gradients and a free water level (FWL) at 4745mTVDSS. The FWL indicated by formation pressure and core data is consistent with the log data. Given the HPHT nature of the gas volume, even low permeability sands are likely to contribute to production. Net sand is therefore defined as equivalent to gross sand. Extensive core indicates that the reservoir is either fine to medium-grained sand or shale and a simple sand flag was devised to describe net, based on matrix density and shale volume. Rhum Sand reservoir quality is variable, being generally moderate but ranging from poor to good (Summary Figures 1 and 2). The highest porosity and permeability was seen in the Upper Reservoir (UR) zone of 3/29 – 2, with 100% net-to-gross (NTG) averaging 16.4 porosity units (PU) and 255 millidarcies (mD) (zonal averages) in a 3.4m thick sand, but the same sand in 3/29a – 4 is only 1m thick with 50% NTG, less than 1 PU and 0.1 mD. The Upper Main Reservoir (UMR) zone ranges in porosity between 3.8 and 11.4 PU, permeability 0.5 to 12 mD and NTG 4 to 96%. Individual beds in the UMR exhibit Darcy-scale permeability. Despite the variability between reservoir zones, the total net reservoir thickness is similar in both wells, being 108m in 3/29 – 2 and 95m in 3/29a – 4. Page 4
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 1.1. 3/29 – 2 Rhum Well Summary – Reservoir Section 3/29 – 2 Reservoir Properties IN CALI 16 0.45 V/V RHOB IN GR 16 1.95 G/C3 DT 2.95 0.2 OHMM SFLU 200 US/F 40 0.2 OHMM METRES -0.15 6 6 200 0 GAPI 200 140 ILD CORE 4520 KCF 4525 31 4530 4535 UR 4507 4540 4511 4545 4550 IRS 4555 20 4560 4532 4565 4570 V/V BVW V/V VSH 0 0.1 0 1 V/V 0 0 V/V 1 0.1 10000 4490 4495 Porosity, % Arith. Perm., mD Geom. Perm., mD 3.4 3.4 100 16.4 669 255 29.2 28.0 96 11.2 250 9 UMR2 19.4 12.7 65 11.4 85 11 20.9 19.1 91 7.4 14 1 LMR MD NTG, % UMR3 K MD 10000 CKHA Net, m UMR1 0 0 1 NET 0 10 4485 50.5 44.4 88 2.8 4 0.1 4500 4505 Averages on total sand flag 4510 4515 4520 4525 Top Main Rhum Reservoir 4530 4535 4540 4580 4545 4585 4550 4590 4555 4561 4595 4560 4600 4565 4605 4570 4610 4575 4580 4615 4580 4620 4585 4625 4590 4630 4595 4635 4600 4640 4605 4645 4610 4650 4615 4655 4620 4660 4625 29 UMR2 19 UMR3 21 4601 50 V/V 1 METRES SWE 0 4480 4575 UMR1 LMR V/V PHIE 0.3 4515 IN CPOR 0.3 4510 10 PHIE Gross, m UR TVDSS 0.1 METRES G/C3 NPHI Depth DRHO -0.4 BS Zone Reservoir Zone 4665 4670 4675 4680 4685 Reservoir not flow tested FWL below base reservoir at 4745 mTVDSS 4630 4635 4640 4645 Page 5
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 1.2. 3/29a – 4 Rhum Well Summary – Reservoir Section -0.15 6 IN GR 16 1.95 0 GAPI 200 140 M1RX 10 METRES 0.1 V/V RHOB TVDSS G/C3 NPHI 16 0.45 METRES -0.4 IN CAL BS 6 Zone IN COREPHIH1 % COREICPHI1 0 G/C3 DT 2.95 0.2 OHMM RV 200 30 % PHIE US/F 40 0.2 OHMM 200 0.3 V/V 4640 4645 KCF 4650 33 4655 4660 4665 UR 4639 4670 4675 IRS 4680 25 4685 4665 4690 4695 4700 4705 UMR1 45 4710 4715 4720 4725 4730 4710 UMR2 22 4735 4740 4745 4750 4755 4732 4760 UMR3 13 4745 4765 4770 4775 4780 4785 4790 4795 LMR 61 4800 4805 4810 4815 4820 4825 4830 4806 4835 4840 4845 4850 LR 48 4855 4860 4865 4870 4875 4880 V/V BVW V/V VSH 0 0.1 MD K 0 1 0 0 V/V 1 0.1 MD 4640 4645 4650 Top Main Rhum Reservoir 4685 4690 4695 • • • • 4700 4705 4710 4715 4720 4725 4730 4735 4740 4745 0.5 50 0.5 0.2 0.1 17.9 0.7 4 3.8 3 0.4 26.8 17.9 67 9.2 70 12 22.3 5.0 22 6.9 1 0.5 UMR3 4635 4680 1.0 UMR2 4630 4675 Geom. Perm., mD 12.9 10.4 81 6.8 18 1 LMR 61.0 45.1 74 6.4 4 0.2 LR 47.6 15.4 32 7.1 1.3 0.2 10000 4625 4670 Arith. Perm., mD UMR1L 10000 V/V K 4620 4665 Porosity, % 0 0 1 4615 4660 NTG, % PHIE 1 METRES SWE NET 0 10 4610 4655 Net, m UMR1U 0 30 Gross, m UR CORE Depth DRHO Zone Reservoir 3/29a – 4 Reservoir Properties FWL DST 2 45 mmscfg/d 270 bbl cond/d CGR 6 bbl/mmscf 6.5% CO2, 10 ppm H2S 4750 4755 4760 4765 4770 DST 1B upper • 3096 bbl water/d 4775 4780 4785 4790 4795 4800 4805 4810 4815 4820 4825 4830 DST 1B lower • No flow 4835 4840 4845 4850 Page 6 Averages on total sand flag
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 2. INTRODUCTION AND SCOPE The Rhum Field contains high pressure and high temperature (HPHT) dry gas (88.8 mol% methane) in late Jurassic thinly-bedded turbidite sands. The sands are informally named as the Rhum Sand and belong to the J74 to J62 sequences. The field has only three well control points: 3/29 – 1, 3/29 – 2 and 3/29a – 4 (Figure 2.1). 3/29 – 1 encountered sands below Cretaceous mudstones that are of inferred late Jurassic age but cannot be dated conclusively. The well took a gas kick, was not logged across the reservoir, and was terminated 3 metres into the sand. 3/29 – 2 (off-crest) and 3/29a – 4 (flank) encountered complete Rhum Sand sequences. In 3/29 – 2 the entire 148-metre gross thickness Rhum Sand reservoir was gas-bearing. The well was not tested because suitable HPHT test equipment was not developed at the time of drilling (1977). Only two valid repeat formation tester (RFT) pressure points were obtained. A single 14-metre core was cut in a thinly-interbedded sand interval. A basic gamma ray-densityresistivity-sonic log suite was obtained. 3/29a – 4, drilled in 2000, encountered 191 metres of gross Rhum reservoir, drilled through a gas-water contact, and was successfully tested. 93 metres of core were cut, out of 191 metres of reservoir (nearly half the entire reservoir sequence). A comprehensive suite of logs and pressure data were acquired. An operations preliminary log interpretation was performed by Production Geoscience Limited (PGL) (Whitehead, 2001). Recognising from 3/29 – 2 core that the reservoir was thinly bedded, high resolution density (ZDL) and resistivity (High Definition Induction Log – HDIL, and 3D Explorer induction log tensor resistivity tool - 3DEX) logs were acquired by Baker Atlas GeoScience (BA), together with Magnetic Resonance Imaging Log (MRIL) and sonic (Cross Multipole Array Acoustilog - XMAC Elite) data. BA performed in-house processing and interpretation of the data (Page, 2001), specifically: • • Depth shifting, bad data repair and log compositing; Extraction of horizontal (RH) and vertical (RV) components of resistivity from 3DEX data via inversion; • Enhancement of vertical resolution of density, neutron, and HDIL logs; • Determination of apparent fluid volumes from MRIL. The BA report should be consulted for log processing details. 2.1. Workscope This report details the updated log analysis incorporating special core analysis (SCAL) data from 3/29a – 4 and also includes a re-analysis of 3/29 – 2. The scope of work comprised: • • • • • • • • • • Quality check and update Geolog database, check environmental corrections and load necessary additional data including PGL curves and SCAL-corrected core data; Review of PGL petrophysical analysis of 3/29a – 4; Update analysis of 3/29a – 4 with previously uninterpreted high resolution log data and new SCAL data. This analysis will improve thin sand bed resolution and water saturation determination; Correct core porosity data for overburden and core permeability data for reservoir conditions. Use core data to calibrate log-derived porosity and permeability; Comparison of porosity and water saturation analysis derived from different tools (nuclear, electric and magnetic resonance imaging logs) and matched to core data; Evaluate whether higher resolution density and resistivity tools have added value to well results and aided net definition; Re-evaluate 3/29 – 2 logs using Archie parameters derived from 3/29a – 4 SCAL; Determine best net sand flag; Generate permeability logs; Confirm free water level; Page 7
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 • • Generate reservoir zone averages; Export data for RMS 3D geological model build. 2.2. Depth Conventions All depths and thicknesses are quoted in metres (m) and unless otherwise specified are logged depth below reference datum. True logged vertical depth below reference datum and true logged vertical depth subsea are indicated as TVD and TVDSS respectively. Drilled depths are indicated as mDD, mTVDDD or mTVDSSDD. Figure 2.1. Rhum Field Location Map B C Nuggets 19b 24c 23a 25c HWC 21 D 23b 24b 24a 25b 10a 11a 11c 29a 28a 29d 30a 28b 30b 29b 28c a 3a 26 4a 3b 4c Bressay 11b Rhum 29c 5b 10/1 1b 5a 4b 4d 2a 3/29a-4 2c 25/1a Frigg 3/29-2 8b 10a 9c 8a 9a 9b 4b 10b 9d 13e 13d 14a 3/29-1 6 10c Bruce 6 15a 5b 4c 4a 1km Page 8
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 3. FIELD AND WELL DATABASE Tables 3.1 to 3.3 list basic Rhum Field information and data availability. Geolog database listings are provided in Appendix 1, identifying the names of best log and core datasets. Note that complete sequence, group, formation and reservoir zone tops from surface to TD are included in the Geolog database as ZONE.SEQUENCE, ZONE.GROUP, ZONE.FORMATION and ZONE.ZONE. Table 3.1. Rhum Field Data PROPERTY VALUE UNITS NOTES LOCATION Field / Block Latitude Longitude Water Depth 3/29a 60 08' 13" 01 42' 50" 108.5 N E metres ca.45km N of Bruce, 35km NW of Frigg 3/29a-4 location 3/29a-4 location MSL - no significant variation across field 4 way dip closure 3.50E+07 1.99E+09 4400 4880 ?4731 4745 345 0 12418 12418 0.17 m2 m3 mTVDSS mTVDSS mTVDSS mTVDSS mTVDSS mTVDSS psia psia psi/ft TRAP Type Area Gross Rock Volume Depth to Crest Lowest closing contour GWC FWL Gas Column Oil Column Original Pressure @ datum Current Pressure @ datum Pressure Gradient Original Temp 149.6 Datum Depth 4745 RESERVOIR Formation Age Type Gross Thickness Net:Gross Porosity average (range) Permeability average (range) Hydrocarbon saturation average (range) WELL TEST PERFORMANCE AOFP Test Kh Test Rate PETROLEUM Gas Gravity Condensate Density Condensate Viscosity Water Viscosity Dew point CGR Gas Expansion Factor Water Formation Volume Factor Condensate Compressibility Water Compressibility Formation Compressibility FORMATION WATER Salinity Resistivity FIELD CHARACTERISTICS GIIP STOIIP (condensate) Recovery Factor (gas) Recovery Factor (condensate) Drive Mechanism Recoverable Gas Recoverable Condensate Rhum Sand Late Jurassic Turbidite Sands 200 0.25 0.09 (0.06-0.12) 45 (0.01 - 530) 86 Reservoir interval drapes Triassic fault block Dimensions approx 10km (N-S) by 5km (E-W) Base Case (range 1.87-2.28 E+09 m3) Probable transition zone above FWL @4745m (welltest Pi 12350psia @4619m) Some evidence for higher pressures in aquifer Reservoir gradient (PVT gradient closer to 0.14 psi/ft) @ 4745 mTVDss (6 Deg /100m apparent res. temp grad. deg C (From Horner plots of wireline logs)) mTVDSS FWL metres fraction v/v mD % Analogous to Brae, but a separate sand system Intra-Kimmeridge Thin-bedded sand units within basin-floor fan Approx - thickens on western flank Average - varies laterally and by reservoir unit Extent of qtz. cement controls resr. quality From core in 3/29a-4 SCAL measurements - log satns. unreliable in thin sands 297 1450 45 mmscf/d 3/29a-4 performance mDm 3/29a-4, DST2 mmscf/d 3/29a-4, DST2, drawdown 575psi, 1/2" choke 0.65 0.788 0.25 0.25 5640 6 384 1.03 air=1 g/cm3 cp at Pi cp at 146deg C psia at 148deg C stb/mmscf scf/rcf rb/stb not yet determined 1 / psia 1 / psia From SCAL on core samples from well 3/29 a4 5.76E-07 7.00E-06 15800 0.075 mg/l ohmm chlorides -unusually low salinity for UJ marine resr. @140deg C 1168 7 70 60 Gas expansion 803 4.23 Bcf mmbbl % % Mean case, range 703-1720 Bcf (p90-p10) Mean case, range 4.2 -10.3 mmbbl (p90-p10) Base case, range of scenarios considered Bcf mmbbl Page 9 Aquifer movement less significant than gas blowdown Probabilistic (Range 458-803-1072 Bcf, P90-P50-P10) Probabilistic (Range 2.75-4.23-4.34 Bcf, P90-P50-P10)
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Table 3.2. Data Availability – Rhum Area Wells Loaded to Geolog Well Date Log Data over Reservoir Mud Type RTE, mamsl Late Jurassic Reservoir Presence 3/24b – 2 1986 N/a OBM 22 3/25a – 3 1977 OBM 24 3/25a – 4 1985 OBM 26.5 3/29 – 1 1973 GR, RHOB, NPHI, ILD, DT GR, RHOB, NPHI, ILD, DT None No late Jurassic reservoir – Shetland Platform well Gas shows in v. thin sands V. thin sands WBM 34 3/29 – 2 1977 WBM 25.2 3/29a – 4 2000 OBM 23.5 Suspended gas producer 3/29b – 3&S1 1992 WBM 26.2 Thin sands GR, RHOB, NPHI, ILD-SFLU, LLD-LLSMSFL, DT MWD plus high resolution wireline ZDL density, 3DEX and HDIL resistivity tools, XMAC Elite sonic, CBIL imager, MRIL GR, RHOB, NPHI, LLD-LLS-MSFL, DT Probably drilled 3m into reservoir Rhum discovery well Table 3.3. Rhum Sand Reservoir Zone Tops 3/29 – 2 3/29a – 4 Zone Top, Zone Top, Zone Top, Zone Top, mMD mTVDSS mMD mTVDSS KCF 4508 4476 4633.5 4606 UR 4540 4507 4666.5 4639 IRS 4544 4511 4667.5 4640 UMR1U 4692.5 4665 UMR1 UMR1L 4565 4532 4710 4683 UMR2 4595 4561 4737.5 4710 UMR3 4615 4580 4760 4732 LMR 4636.5 4601 4773 4745 LR 4834.5 4806 Heather 4688 4651 4883 4855 Devonian 4852 4810 Basement 5147 5105 TD 5165 5123 5060 5031 KCF – Kimmeridge Clay Formation, UR – Upper Reservoir, IRS – Inter Reservoir Shale, UMR – Upper Main Reservoir, LMR – Lower Main Reservoir, LR – Lower Reservoir. Zone Name Page 10
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 4. FIELD TEMPERATURE AND PRESSURE As stated in the Introduction, Rhum is considered to be an HPHT field. Wells with undisturbed bottomhole temperature above 150oC (302oF) are classed as high temperature. Those with wellhead pressure greater than 10,000 psi or a maximum anticipated downhole pore pressure exceeding an 0.8 psi/ft hydrostatic gradient are considered high pressure (Baird et al., 1998). The highest reliable corrected bottom hole temperature (BHT) registered while logging in 3/29a – 4 was 155oC at 4,919.4 m (Run 4A in 8.5-inch hole). This would yield an extrapolated BHT at total depth (TD - 5,060 m) of 163.3oC (Watts, 2001). A temperature gradient for the Jurassic and Devonian interval of 5.94oC/100m was computed from BHT data from Runs 3 and 4 (Watts, 2001). For log analysis purposes, the near-bore formation temperature at time of logging is more important. TD logging Run 5 registered 141.1oC at 4,927mTVDSS after 22.6 hours no circulation and this value was combined with the temperature gradient data to determine nearbore reservoir temperature distribution at time of logging (Figure 4.1). The maximum measured shut in pressure recorded at the wellhead in 3/29a – 4 was 10,190 psi. The maximum downhole pressure in the gas leg was 12,418 psi at 4,745 mTVDSS in 3/29a – 4. The maximum downhole pressure in the water leg was 13,493 psi at 4,838 mTVDSS in 3/29 – 2 (Figure 4.2). More information on formation pressure is given in Section 8. Figure 4.1. 3/29a – 4: Temperature Gradient used in Log Analysis Temperature Gradient, 3/29a-4 -4550 100 -4600 110 120 130 140 150 160 Top KCF -4650 -4700 Jurassic temperature gradient 5.94 degC/100m Depth, TVDSS -4750 -4800 -4850 Top UMR1 Sand -4900 Run 5 log temp – 141.1degC @ 4927m -4950 -5000 TD @ 5031m -5050 -5100 Temp., degC Page 11 170
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 4.2. Rhum Field Formation Pressures Rhum Reservoir Pressure psi 12000 4300 12200 12400 12600 12800 13000 13200 13400 13600 4400 depth tvdss 4500 crest 3/29-1 4600 3/29-2 3/29a-4 4700 4800 4900 Page 12
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 5. WELL – BY – WELL EVALUATION This section describes the updated petrophysical evaluations conducted on 3/29a – 4 and 3/29 – 2. 3/29a – 4 was evaluated first, then 3/29 – 2 was reanalyzed using the SCAL data from 3/29a – 4. 5.1. 3/29a – 4 Review 5.1.1. 3/29a – 4 Data 3/29a – 4 was drilled with a synthetic oil-based mud (SOBM). Hole deviation is low (maximum 5.7 degrees at 4947m). The well reached TD at 5060m in the Heather Formation. Log and test data are listed below (Tables 5.1 and 5.2). Log curve mnemonics are listed in Appendix 1. Four intervals were perforated and tested. Note that only the UMR zone flowed gas. Deeper intervals were perforated and tested because the initial evaluation conducted by PGL indicated deeper hydrocarbons. The cause of this was use of an incorrect estimated formation water resistivity (RW) value. The water recovered on test allowed refinement of the RW value used in this updated analysis. Logging was conducted by BA and was problematic, with multiple runs being made. Intermediate logs suffered from tool sticking. TD logs were of better quality although there were still zones of sticking and TD logs only reached a maximum depth of 4980m, not reaching the well TD of 5060m. Log data were loaded to Geolog (Appendix 1). 93m of core were cut and cored intervals are listed in Appendix 2. Conventional and SCAL core analyses were conducted by Corex and Integrated Core Consultancy Services Limited (ICCS). ICCS data were generally considered to be of better quality and were used for log calibration purposes. SCAL data are reviewed in Appendix 3. Key input curves and data are plotted on the CPI, Enclosure 1. Table 5.1. Well 3/29a – 4 Log Data Summary for Zones of Interest Run No. Logs Run Interval Logged, mMD Date Run LWD 1215 WL3A WL4A GR-MPR-MAP-DIR (+CCN-ORD on run 14) FMT-GR-CHT GR-HDIL-3DEX-ORIT-XMACIITTRM ZDL-CN-DSL-TTRM FMT-GR-CHT RCI-GR-TTRM RCI-GR-TTRM RCI-GR-TTRM FMT-GR-CHT FMT-GR-CHT MRIL-GR-TTRM 4525-4961 11/1029/11/00 17/10/00 30/11/00 WL4A WL4A WL4A WL4B WL4C WL4B WL4C WL4A WL4B MRIL-GR-TTRM WL4D RCI-GR-TTRM WL4E RCI-GR-TTRM WL4A HDIP-CBIL-GR-TTRM WL5A GR-HDIL-XMAC-ORIT-TTRM* WL5A ZDL-CN-DSL-TTRM* WL5A DMAG-GR* *TD logs marked with an asterisk. Page 13 4664-4693.6 4963-4514 4910-4514 4717-4880.5 4717.5-4834.6 4717.5-4783.5 4790-4859 4784.5-4861.8 4733.9-4882 Failed – no data 4900-4675 4788-4851.5 4835 4910-4514 4980-4650 4915-4776 4510-130 Hole Size, inches 8.5 8.5 8.5 1/12/00 1/12/00 1/12/00 2/12/00 2/12/00 3/12/00 3/12/00 4/12/00 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 4/12/00 5/12/00 5/12/00 6/12/00 11/12/00 11/12/00 12/12/00 8.5 8.5 8.5 8.5 8.5 8.5 8.5
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Table 5.2. Well 3/29a – 4 Test Data Test No. DST1A DST1B DST2A Top of Perforated Interval, mMD 4844 4777 4844 4692 Bottom of Perforated Interval, mMD 4883 4829.5 4833 4735 Shot Spacing, SPF 6 6 6 6 Result LR zone – no flow LMR & LR zones – 3096 BWPD, 15800 mg/l salinity UMR zone – 45 mmscfgpd, CGR 6.4 stb/mmscf Log data were loaded to Geolog by previous users during well operations. Existing naming conventions were confusing and have been updated (see Appendix 1). Best datasets are depth-referenced to the Run 5A down log (BA_FINAL_LORES_GR_REF_1 or BEST.GR_REF_1 reference gamma ray log). GR_REF should not be used for analysis since it is a mix of centralized and decentralized sensor data and is for depth reference purposes only. The best set of logs are the ones in sets prefixed BA_FINAL, and key logs have been copied from BA_FINAL sets to a single BEST set. Operations petrophysical analysis was performed by PGL (Whitehead, 2001) with BA Geoscience conducting additional studies (curve processing and corrections, MRIL data analysis and thin bed resistivity modelling). BA made necessary environmental corrections but PGL additionally corrected the neutron CNC log for pressure, mud weight and borehole temperature (curve named CCNC). Both BA and PGL spliced logs to obtain coverage over bad data areas. The BA composited logs were used in the PGL analysis. The first step in this review was to understand the origin and significance of existing Geolog data and to update the database with formation tops from OpenWorks and with perforations/test data. A petrophysical database was constructed within Geolog. Database specifics, including environmental corrections and core shifts applied are provided in Appendix 1 and 2. SCAL results are provided in Appendix 3. 5.1.2. Review of PGL Analysis A layout was built to show PGL results (SK_329A_4.layout). This was used to check we had the correct PGL data set. All the curve data provided by PGL are retained in the Geolog dataset called PGL (input curves and calculated curves). As a background check on the PGL method and software the PGL analysis was partially duplicated. Input curves matching those used by PGL are in the BEST_PGL dataset. Calculated curves are in the CALC_PGL data set. 5.1.2.1. Environmental Corrections Note that the only environmental correction made by PGL was to the CNC log. PGL believed that BA had made all other required corrections but this was not the case. Corrections are required for mud weight to the GR, density and PE logs. Resistivity logs were boreholecorrected in real-time. The CNC log is borehole-corrected compensated (caliper and salinity) neutron logs. The CNCC log is additionally corrected for pressure, mud weight and borehole temperature. The PGL environmental correction (PGL.CNCC) was duplicated in Geolog (BEST_PGL.CNCC) as a check on the PGL method. Table 5.3 lists the input parameters derived from the Run 5A log header. There was good agreement between the two curves. The same corrections were applied to the BEST.NPHI and BEST.CNHR curves. Page 14
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Table 5.3. CNC Log Environmental Correction Parameters Parameter CNC Tool Type Standoff Top Log Interval Temperature (TLT) Top Log Interval Depth (TLI) Bottom Log Interval Temperature (BLT) Bottom Log Interval Depth (BLI) Mud Weight (DFD) Bit Size (BS) Mud type Mud oil/water ratio Whole mud chlorides Mud salinity Mud contains barite? Units Inches O F Metres MD O F Metres MD Lb/gal Inches Mg/l Mg/l Value 2446XA Decentralized 60.8 128 286 4899 15.94 8.5 SOBM 82/18 23,750 38,229 Yes, 30.65% 5.1.2.2. Shale Volume (VSH) Computed by reservoir interval using input parameters listed in PGL report (Whitehead, 2001, Appendix 2). VSH computed using gamma ray from resistivity logs (VSHGR), neutron (VSHN) and neutron/density (VSHDN). Good agreement with PGL curves. PGL comparison is in CALC_PGL. 5.1.2.3. Effective Porosity (PHIE) Effective porosity computed using PGL constants and Bateman-Konen density-neutron method. Resulting curve (CALC.PGL_PHIE) is very similar. 5.1.2.4. Water Saturation (SW) The PGL petrophysical analysis was run using the 3DEX vertical resistivity component, RV, for true formation resistivity (RT) as input to the Indonesia Equation (RV gives a better measure of thin bed resistivity than horizontal resistivity, RH) over the UMR1. Below the UMR1, the HDIL 120-inch depth of investigation (M2RX) curve was used for RT. The curve is PGL.RTCOMP. However, the RV curve cannot be used to compute saturations using the Indonesia Equation because the Indonesia Equation is designed to use horizontal resistivity measured in parallel along beds rather than in series across beds. The result would tend to underestimate SW. The 3DEX data must be interpreted using BA software with informed user input. Since this method was not valid it was not repeated. 5.1.3. MRIL Processing MRIL analysis method is described by Page (2001). MRIL data are loaded in Geolog in the set BA_FINAL.MRIL. MRIL curves are displayed on the enclosed CPI (track 16, Enclosure 1). Note that the MRIL curves displayed have been summed to indicate the different fluid fractions: • PHS, total porosity = MCBW + MPHI PHS is the sum of clay-bound water (MCBW) plus mobile fluids or effective porosity (MPHI). • MPHI, effective porosity = MBVI + MFFI MPHI is the sum of capillary-bound water (MBVI) plus free fluids (MFFI). • MFFI may be mobile water (MWATER), oil (MOIL) and gas (MGAS). • MWATER = MBVI + MRIL_WATER Page 15
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 • MOIL = MWATER + MRIL_OIL • MGAS = MOIL + MRIL_GAS • PHS also equals MGAS + MCBW (in this case the sum MGAS equals MPHI) In this case MOIL represents the invaded phase of the oil-base mud and not oil in the formation. Summed curves are located in the set PGL. Note that PGL.MRIL_SW (track 14, Enclosure 1) measures irreducible SW, and therefore only indicates true SW above the free water level. The MRIL tool has a 2-foot vertical resolution and the resultant curves are very smooth compared to electric log curves. 5.1.4. New Petrophysical Analysis Best input curves are located in the BEST Geolog dataset. Computer-processed log interpretation (CPI) plots are enclosed (Enclosure 1 – detailed analysis, Enclosure 2 – simplified display). 5.1.4.1. Environmental Corrections The gamma ray (GRR) log is corrected for hole size and mud weight since there is no evidence of prior corrections having been made. The corrected curve is BEST.GRR. High resolution density (BEST.DNHR), neutron (BEST.CNHR) and HDIL induction log (BEST.M1R) data were used for the updated analysis. DNHR and PE curves were corrected for borehole size. DNHR was renamed as RHOB (bulk density). CNHR log corrected as described above, and renamed as NPHI. HDIL curves were corrected by BA for borehole conditions. Zones where HDIL component curves do not overlie each other are likely due to stick and pull effects, which were corrected as far as possible, and not due to invasion. 5.1.4.2. Analysis The petrophysical analysis was run from top Kimmeridge Clay Formation to TD, which included the Rhum reservoir sands and the underlying Devonian interval. Input constants are listed in Table 5.4. Where the same value is indicated in the table this is because there was insufficient difference or data to vary the constants between intervals. Note that the same input parameters were applied to the Devonian interval as for the Rhum Sand, and the Devonian analysis should be considered quick-look only. 5.1.4.3. VSH The best VSH method was considered to be a normalized gamma ray because density and neutron logs could be affected by gas in the shales that is not easily detected or corrected for using Geolog. The common method of taking the minimum of VSH from density, neutron and GR methods is flawed in gas reservoirs where the gas effect will cause underestimation of shale on the neutron and density logs. Different matrix and shale constants were used for the LR zone that exhibited a considerably higher GR than the rest of the reservoir, indicating a different shale type. VSH is computed from BEST.GRR. See GR histogram (Figure 5.1) and constants table for input values. Resulting curve is CALC.VSH_GR (track 17, Enclosure 1). Page 16
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 5.1. GR Response Histograms Frequency Histogram of BEST.GRR_COR_1 Well: 3_29A-4 4633.5 - 4894.0 METRES Filter: Frequency Histogram of BEST.GR_1 Well: 3_29-2 Intervals: KCF, UR, INTER RES SHALE, UMR1, UMR2, UMR3, LMR, LR, LKCF Filter: 1.0 0.06 1.0 0.025 0.9 0.9 0.05 0.8 0.8 0.020 0.7 0.7 0.04 0.6 0.6 0.015 0.5 0.5 0.03 0.4 0.02 0.4 0.010 0.3 0.3 0.2 0.005 0.2 0.01 0.1 0.1 Possible values Missing values Minimum value Maximum value Range 242 0 14.59800 189.63300 175.03500 Mean Geometric Mean Harmonic Mean 139.62461 126.97939 99.56522 Possible values Missing values Minimum value Maximum value Range Mean Geometric Mean Harmonic Mean GR_MA 24 GR_SH 183 6837 0 20.00517 341.82709 321.82192 156.00152 128.23745 95.30654 Variance Standard Deviation Skewness Kurtosis Median Mode 1776.87826 42.15303 -1.46019 4.87954 145.31250 171.25000 Page 17 6405.42571 80.03390 -0.05039 2.07035 168.41034 26.25000 GR_MA 27 GR_SH 233 350 315 SH 280 245 210 175 140 105 35 MA Statistics: Statistics: Variance Standard Deviation Skewness Kurtosis Median Mode 0.0 0 250 225 SH 200 175 150 125 100 75 50 25 MA 70 0.000 0.0 0 0.00
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Table 5.4. Log Analysis Constants Parameter Fluid Type A DT_MA DT_SH DT_FL GR_MA GR_SH M MUD TYPE NPHI_COAL N NPHI_FL NPHI_MA NPHI_SH PHIE_MAX PHIT_SH RES_SH RHO_COAL RHO_DS RHO_FL RHO_MA RHO_SH RHO_W RW RW_TEMP SPI_MAX Units US/F T US/F T US/F T GAPI GAPI V/V V/V V/V V/V V/V V/V OHM -M G/CC G/CC G/CC G/CC G/CC G/CC OHM -M o C V/V Gas 1.1 55.5 UR/Int. Res Sh Gas 1.1 55.5 Gas 1.1 55.5 UMR3/LM R Water 1.2/1.1 55.5 Gas 1.1 55.5 Water 1.1 55.5 Water 1.1 55.5 95 90 90 85 90 90 85 210 210 210 210 210 210 210 27 233 1.9 SOB M N/A 1.7 1 0.017 0.559 0.3 0.052 3.3 27 233 1.9 SOBM 27 233 1.9 SOBM 27 233 1.9 SOBM 27 233 1.9/2.1 SOBM 43 318 1.9 SOBM 43 318 1.9 SOBM N/A 1.7 1 -0.017 N/A 1.7 1 -0.017 N/A 1.7 1 -0.017 N/A 1.7 1 -0.017 N/A 1.7 1 -0.017 N/A 1.7 1 -0.017 0.559 0.3 0.052 5.9 0.559 0.3 0.052 6.7 0.559 0.3 0.052 7.1 0.559 0.3 0.052 5.6 0.559 0.3 0.052 7.2 0.559 0.3 0.052 7.2 N/A 2.66 0.39 2.647 2.573 1 0.075 N/A 2.66 0.39 2.647 2.573 1 0.075 N/A 2.66 0.39 2.647 2.573 1 0.075 N/A 2.66 0.39 2.647 2.573 1 0.075 N/A 2.66 0.7 2.647 2.573 1 0.075 N/A 2.66 0.7 2.647 2.573 1 0.075 N/A 2.66 0.7 2.647 2.573 1 0.075 140 0.1 140 0.1 140 0.1 140 0.1 140 0.1 140 0.1 140 0.1 KCF UMR1 UMR2 LR LKCF Underlined values are derived from core. 5.1.4.4. PHIE Porosity was computed from density, density/neutron (Bateman-Konen method) and sonic (Wyllie method) logs. Log analysis matrix and fluid constants are included in Table 4.4. Computed log porosities were calibrated against core. Core porosities were corrected for overburden using a factor of 0.972 obtained from 3/29a – 4 SCAL analysis, using the Teeuw (1971) method (Appendix 3). Overburden-corrected data sets are suffixed _OBC. This is a very small correction reflecting the well-cemented nature of the rock. There are no coals in the reservoir. High resolution density and neutron logs (DNHR and CNHR with 1.5-inch sampling) were used as input, with bad data gaps infilled by lower resolution data (track 6, Enclosure 1). The best match to core data was obtained using the density method (track 12, Enclosure 1). Sonic porosity gave a good match to core in the gas leg, but was too low in the water leg. The water leg match could not be improved without reducing reservoir fluid sonic travel time (DT_FL) excessively. The density porosity calculation assumes a matrix density (RHO_MA) of 2.647 g/cc. Core grain density values are predominantly around 2.647 g/cc except for a small percentage of lower grain densities in the range 2.48 g/cc to 2.58 g/cc (track 7, Enclosure 1). Page 18
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Note that the lower the grain density the lower the computed porosity. If a value of RHO_MA is used that is too high, the computed porosity will also be too high. This is relevant because the Lower Reservoir interval 4850 – 4865 m contains four beds with computed porosity in the 15 to 20 porosity unit (PU) range. However, MRIL porosities are lower, around 5 PU (curve PGL.MPHIE, track 16, Enclosure 1). A porosity of 5 PU can be matched by reducing RHO_MA to 2.5 g/cc. Petrographical studies (Paintal, 2002) did not identify significant amounts of lower density material such as clays, felspar, organic material or residual hydrocarbons in any of the core samples. There was not therefore a good case for lowering RHO_MA, and the anomaly remains. Reservoir fluid density (RHO_FL) was computed at 0.39 g/cc in the gas leg, using a core porosity to log density regression (Figure 5.2). This matches the measured pressure gradient of 0.17 psi/ft (equivalent to 0.39 g/cc). There were insufficient core data to get a reliable RHO_FL value in the water leg. The water leg RHO_FL value was selected based on an SOBM density of 0.7 g/cc. The MRIL log indicates that SOBM is the invaded phase. Computed porosity curves are named CALC.PHIE_DEN or CALC.PHIE (density method), CALC.PHIE_DN (density-neutron method) and CALC.PHIE_SON (Wyllie sonic method). BA (Page, 2001) computed an effective sand fraction porosity (see Geolog curve BA_FINAL_REPORT.PESD_1; track 13 on Enclosure 1) based on an anisotropic thin bedded, laminar shaly sand model utilizing the 3DEX data. This is intended to give a better volumetric characterization of porosity in thin sands by removing thin laminar shale effects. In thicker sands the result matches the density porosity. In the KCF a number of thin sands with 15 PU porosity are identified by this method that would be productive. However, comparing the PESD curve to core description indicates that the PESD curve over-estimates porosity in thick shaly units. Therefore the PESD curve should be treated with caution. Given the difficulty of identifying these sands with conventional log analysis it is recommended that the entire reservoir interval including the KCF is perforated if possible. Figure 5.2. 3/29a – 4 Core Porosity vs Log Density Crossplot in the Gas Leg 3.00 2.70 2.40 2.10 1.80 1.50 1.20 0.90 0.60 0.30 0.00 0 Well: 3_29A-4 4633.5 - 4760.0 METRES Filter: 100 100 40 30 30 20 20 10 10 0 0 3.00 40 2.70 50 2.40 50 2.10 60 1.80 60 1.50 70 1.20 70 0.90 80 0.60 80 0.00 90 0.30 90 CORE.COREICPHI1_OBC_1 () 0 32 32 0 0 CORE.COREICPHI1_OBC_1 vs. BEST.DNHR_1 Crossplot BEST.DNHR_1 (G/CC) Functions: gasdens : Regression Logs: BEST.DNHR_1, CORE.COREICPHI1_OBC_1, CC: 0.628980 y = (117.058 - 44.1727*(x)) Page 19
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 5.1.4.5. SW Two approaches were applied to SW determination: • • Use 3DEX RV data and process using method developed in-house by BA. Use M1RX high resolution data from HDIL tool for comparison with 3DEX results. M1RX curve is 120-inch depth of investigation and 1-foot sample rate. Note that PGL analysis used an incorrect hybrid of M2RX (2-foot sample rate curve) and RV curve from the 3DEX. Both methods made use of new SCAL parameters (Table 5.4 and Appendix 3). The previous PGL interpretation used defaults a=1, m=n=2. SCAL parameters are interpolated to the appropriate confining pressure. An ‘a’ value of 1.1 was used for all zones except the UMR3 (a=1.2). An ‘m’ value of 1.9 was used for all zones except the UMR3 (m=2.1). An ‘n’ value of 1.7 was selected for all zones, although there was a range on measured values. The SCAL data indicated n=1.61 for UMR1 and 1.79 for UMR3. The 1.7 value is the mid point of this range. The LMR ‘n’ value was very low at 1.12, but this was rejected as unlikely. Such a low value would increase the hydrocarbon saturation in the LMR, in a zone which did not flow any gas on test. An RW of 0.075 ohm-m at 140oC was used in the computation of SW. This was obtained from a DST1B water sample in 3/29a – 4. The RW value equates to a salinity of 22,500 mg/l NaCl. The measurement was presumably made on a water sample using a conductivity meter. Laboratory water analysis data are presented in Table 5.5. The equivalent salinity expressed as NaCl is approximately 27,500 mg/l. This would give an RW of 0.062 ohm-m at 140oC. RW measurements were also made on brine extracted from core samples (Table 5.6). The average of the core extract RW is the same as the test water analysis RW. The most reliable measurement of RW is by direct meter reading. The measured range is actually quite small in this case: the difference between Sw computed using 0.062 ohm-m compared to 0.075 ohm-m is approximately 1.5 saturation units (SU). Earlier analysis by PGL had used an RW of 0.035 ohm-m at 140oC (the same value as quoted in a BP file note on 3/29 – 2 petrophysical analysis, author and date unknown). Although this value was corrected to 0.075 ohm-m in the PGL report (PGL, 2001), PGL used the 3DEX Rv curve as an RT input to the Indonesia Equation. As explained in Section 4.1.2, this approach is not endorsed by BA. Table 5.5. 3/29a – 4 DST1B Water Analysis Ion Na K Mg Ca Fe Sr Ba Cl Br SO4 HCO3 Total Dissolved Solids Equivalent NaCl salinity PH Reference: McBride and Cook, 2001. Concentration mg/l 10340 116 35.2 245.4 3.2 175.8 350.4 16130 80.02 0 1075 28551.02 ~27500 7.25 Page 20
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Table 5.6. 3/29a – 4 RW from Core Brine Extracts Depth, mbrt 4762.55 4769.25 4779.44 Filtrate Invasion, fraction 0.063 0.081 0.083 RW at 20oC, ohm-m RW at 140oC, ohm-m 0.188 0.299 0.250 Average: 0.048 0.077 0.064 0.063 Reference: Mitchell, 2001. The Indonesia Equation was used to compute effective SW (SWE) from the M1RX log. Since, none of the SCAL samples exhibited significant electrical shaliness, with the reservoir shale contribution to total conductivity under fully water saturated conditions being under 10% (ICCS, 2001), the Archie Equation would have yielded the same result. The resulting curve is CALC.SWE. CALC.BVW is the unflushed zone volume of water. SWE computed from 3DEX data by BA is CALC.SWE_3DEX. SWE_3DEX was computed using the Waxman-SmitsThomas Equation (Page, 2001). The MRIL computed SW is PGL.MRIL_SW. The curves are compared on the CPI log (track 14, Enclosure 1). The highest gas saturations, which match the core SW, are the MRIL values. The 3DEX SWE matches MRIL gas saturations in thicker sands but not in the thinly-bedded UMR2. The HDIL under-estimates gas saturations. As noted in Section 5.1.3, the MRIL SW curve represents irreducible SW and is not valid below the free water level of 4745m TVDSS. 5.2. 3/29a – 2 Review 3/29 – 2 was drilled with a water-based mud (WBM). The hole is vertical. The well reached TD at 5165m in the Devonian. Log data were re-analysed using the input parameters derived from 3/29a – 4 SCAL. Log curves were already loaded to Geolog by previous workers and it is assumed that the curves have been corrected appropriately. 5.2.1. New Petrophysical Analysis Input and calculated curves are plotted on the CPI (Enclosure 3). 5.2.1.1. VSH VSH was computed as a normalised GR, with GR_MA of 24 GAPI and GR_SH of 183 GAPI (Figure 5.1) for all zones. Note that this well does not have a LR unit. The computed curve is CALC.VSH_GR. 5.2.1.2. PHIE PHIE was calculated from the density log, the resulting curve is called CALC.PHIE. RHO_FL of 1.0 g/cc for water-base mud was used. Other input parameters are the same as 3/29a – 4. The log curve cannot match core porosities because the density log cannot resolve the very thin sands (15 to 20cm) in UMR2. Core data are used to replace the porosity curve over the UMR2, this curve is CALC.PHIE_WCORE. 5.2.1.3. SWE Input parameters Rw, a, m and n were as 3/29a – 4, and included new SCAL parameters (Table 5.4). Note that the previous 3/29 – 2 interpretation used an RW of 0.035 ohm-m instead of the preferred 0.075 ohm-m at 140oC. Input RT was the deep induction (ILD) curve. The resulting curve is CALC.SWE. 5.2.1.4. Lower Reservoir Section There is very little reservoir potential below the Lower Reservoir in 3/29-2, from 4711m to TD. Input parameters used were: RHO_MA 1.66 g/cc, RHO_FL 1.1 g/cc, RHO_SH 2.537 g/cc, Page 21
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 DT_MA 55 us/ft, DT_FL 155 us/ft, DT_SH 100 us/ft. Archie parameters as for main reservoir (Table 5.4). Specific intervals of potential interest are: • Heather Sand from 4711 to 4720m: Tight sand with density porosity less than 5 PU and sonic porosity up to 9.6 PU. The interval 4720 to 4724m has slower sonic (from 60 to 90 us/ft) than the sand immediately above. The slow sonic gives higher apparent porosity, up to 16.6 PU, but density porosity is zero (the porosity curve CALC.PHIE_WCORE on Enclosure 3 indicates sonic porosity spliced in below top LR, which is optimistic but highlights potential thin sands). GR and resistivity are relatively low and cuttings descriptions indicate that the lithology may be a soft limestone. All intervals are waterbearing assuming the same RW as the main Rhum reservoir (0.075 ohm-m at 140oC). • Devonian Sand from 4852 to 4870m MD: The density log is missing over 4840 to 4856m. The interval from 4861.5 to 4870.5m (log depth) was cored. Core porosity is in the range 1.6 to 2.2%, average 1.9%. Core permeability range is 0.02 mD to 0.31 mD, with a geometric average of 0.028 mD (all Klinkenberg corrected). Sonic porosity up to 4 PU maximum is in line with core data, but average Devonian porosity is very low. The rest of the Devonian interval has zero log porosity. SW is 100 SU throughout the Devonian interval, assuming the same RW as in the main Rhum reservoir. Page 22
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 6. LITHOLOGY ANALYSIS Core description indicates that all of the cored Rhum reservoir consisted of white fine to medium grained sand or dark grey organic-rich pyritic mudstones, with no other significant lithologies. Thus a binary sand/shale description matched the actual reservoir lithology. A sand/shale flag was required as the net flag, since in this type of HPHT reservoir even low permeability rock contributes to gas flow. The sand/shale flag was also developed as part of the RMS geological model build for Rhum, and to calibrate seismic attribute maps of sand/shale distribution. The log is a continuous flag curve of the form 0 = shale and 1 = sand. This section describes the method used to derive the sand/shale flag and QC against core data. The Rhum Field wells have very good core coverage: 50% of the gross reservoir interval in 3/29a – 4 is cored and this includes the entire gas-bearing zone. 6.1. Methodology The sand/shale flag was obtained from a cross-plot of derivative curves VSH, apparent matrix density (RHO_MAA) and total porosity (PHIT). Apparent matrix properties such as RHO_MAA are generated in Geolog by the Apparent Matrix Properties module (appmat.lls) to be found under Petrophysics/Parameter Picking. VSH was computed as described in Section 4, from the GR log only. A plot of GR against depth (Figure 6.1) indicates a response difference between the two wells across the reservoir. However the VSH from GR is normalized based on sand matrix and shale end-points for each well (Figure 5.1), so that the VSH plots should be directly comparable although the GR plots are not. The shale baseline is derived from the Kimmeridge Clay above and below the turbidite sand intervals. Porosity is computed from RHOB alone, matching the resulting output to core porosity data by varying RHO_FL. Well 3/29a – 4 cored 93m of 191m gross reservoir (nearly 50 percent of the gross reservoir interval). Well 3/29 – 2 had 14m of core in the UMR2 zone only. A plot of RHOB against depth (Figure 6.2) indicates a similar response between the two wells across the reservoir, and curve normalization was not considered necessary. Note that the high density zone in 3/29 – 2 between 4650 and 4700 mTVDSS is a dense pyritic shale below the reservoir interval. RHO_MAA is computed by Geolog as (RHOB – PHIT*RHO_FL)/(1-PHIT). Required inputs are: • • • • • • RHO_MA matrix density from core (2.647 g/cc). RHOB from the density log. RHO_FL the mud filtrate density (based on match to core data, this varied between 0.39 g/cc in the gas leg of 3/29a-4 and 1.0 g/cc in the water leg of 3/29-2). RHO_W is formation water density (1.02 g/cc based on 22,500 mg/l NaCl). RHO_DSH is dry shale density (2.66 g/cc). RHO_SH is shale density (2.573 g/cc). The apparent matrix photoelectric absorption (U_MAA) is generated by the Geolog appmat.lls loglan module. It can be a useful parameter for differentiating minerals in a U_MAA vs RHO_MAA cross plot (Doveton, 1994). It is computed as U /(1-PHITapparent) where U is the volumetric photoelectric absorption. Figure 6.3 is a crossplot of RHO_MAA vs U_MAA with the positions of key minerals indicated. The Z-axis is VSH. Sand points fall between quartz and calcite, shale points fall slightly to the right of the main kaolinite-illite field. The shales contain finely disseminated pyrite and the iron in the pyrite would increase the U_MAA values (in a comparable way to presence of iron-rich chlorite). However, the U_MAA values could be shifted to the right due to inaccuracies in the computation parameters. Note that the RHO_MAA range for sands and shales is as expected from mineral types. The RHO_MAA/U_MAA/VSH cross plot (Figure 6.3) could be used directly to generate a sand/shale flag. However, the validity of the U_MAA data was uncertain. An alternative Page 23
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 RHO_MAA/PHIT/VSH cross plot was investigated (Figure 6.4). The VSH colour fill indicates that shale tends to have RHO_MAA>2.8 and VSH>0.4. There is no PHIT distinction between sand and shale. The sand/shale flag was generated by drawing a polygon around the shale points in the region RHO_MAA>2.8, VSH>0.4 and PHIT<0.14, and having Geolog compute a sand/shale log from this. Figure 6.1. GR vs Depth Plot: 3/29 – 2 & 3/29a – 4. Figure 6.2. RHOB vs Depth Plot: 3/29 – 2 & 3/29a – 4. 0 2.95 2.85 2.75 2.65 2.55 2.45 2.35 2.25 2.15 2.05 1.95 300 270 240 210 180 150 120 90 60 0 30 0 8169 8169 0 4750 4750 4800 4800 4800 4850 4850 4850 4850 4900 4900 4900 4900 1.95 300 BEST.RHOB (G/C3) Well Legend: 3_29-2 3_29A-4 Figure 6.3. Crossplot – RHO_MAA vs U_MAA: 3/29a – 4 Reservoir Figure 6.4. Crossplot – PHIT vs RHO_MAA: 3/29 – 2 and 3/29a – 4 Reservoir LITH.RHO_MAA vs. LITH.PHIT Crossplot 2.500 2.500 2.555 2.555 47 0.300 0.270 0.240 0.210 0.180 0.150 0.090 0.060 0.030 Well: 3_29-2 3_29A-4 Range: Intervals Filter: 2 0 6438 6440 0 0.000 50.0 45.0 40.0 35.0 30.0 25.0 20.0 15.0 5.0 10.0 0 Well: 3_29A-4 4633.5 - 4894.0 METRES Filter: 0 7480 7527 0 2.832 2.832 DOLOM 2.888 2.888 SMECTITE 2.943 ANHYDR 2.998 2.998 KAOLIN LITH.RHO_MAA (G/C3) 2.777 3.054 2.725 2.725 2.800 2.800 2.875 2.875 2.950 2.950 3.025 3.025 3.100 2.722 CALCITE 2.943 2.650 3.100 3.175 3.175 3.250 3.250 2.666 2.777 3.054 ILLITE LITH.U_MAA_1 (B/C3) 0 0.300 0.270 0.240 0.210 0.180 0.150 0.120 0.090 0.060 50.0 45.0 40.0 35.0 30.0 25.0 20.0 15.0 3.220 10.0 3.165 3.220 5.0 3.165 0.030 3.109 CHLORITE 0.000 3.109 0.0 LITH.RHO_MAA_1 (G/C3) 2.722 2.575 2.611 QUARTZ 2.666 2.500 2.575 2.650 ORTHOCL 2.611 2.500 LITH.PHIT (V/V) 1 0 1 Color: LITH.VSH_GR_2 Color: LITH.VSH_GR Well Legend: 3_29-2 Page 24 3_29A-4 0 LITH.RHO_MAA_1 vs. LITH.U_MAA_1 Crossplot 0.0 3_29A-4 0.120 90 BEST.GR_COR (GAPI) Well Legend: 3_29-2 2.95 4750 4800 2.85 4750 2.75 4700 2.65 4650 4700 2.55 4650 4700 2.45 4650 4700 2.35 4650 2.25 4600 2.15 4600 2.05 4600 REFERENCE.TVDSS (METRES) 4600 270 4550 240 4500 4550 210 4500 4550 180 4500 4550 150 4500 120 4450 60 4400 4450 0 4400 4450 30 4400 4450 REFERENCE.TVDSS (METRES) 4400 0 Well: 3_29-2 3_29A-4 Range: Intervals Filter: 0 7949 8169 0 220 REFERENCE.TVDSS vs. BEST.RHOB Crossplot Well: 3_29-2 3_29A-4 Range: Intervals Filter: 0 REFERENCE.TVDSS vs. BEST.GR_COR Crossplot
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 The key discriminant in the cross plot method is RHO_MAA. The 2.8 g/cc cut off point is confirmed by plotting RHO_MAA for both wells as a histogram (Figure 6.5). Note that the high density ‘tail’ in the 3/29a – 4 distribution is a shale unit not present in 3/29 – 2. The VSH distribution is diffuse although showing a clear trend (Figure 6.6) and a VSH cut-off alone will not separate sand from shale. As stated above, PHIT does not differ sufficiently between sand and shale. This is because many of the thinly interbedded sands are tightly cemented with quartz and are low porosity. Figure 6.5. RHOB Histogram: 3/29 – 2 & 3/29a – 4. Figure 6.6. RHO_MAA vs VSH Cross Plot: 3/29 – 2 & 3/29a – 4. 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.9 0.80 1.0 0.040 0.90 0.045 1.00 0 Well: 3_29-2 3_29A-4 Range: Intervals Filter: 0 7527 7527 0 2.500 2.500 2.575 2.575 2.650 2.650 2.725 2.725 2.800 2.800 2.875 2.875 2.950 2.950 3.025 3.025 3.100 3.100 3.175 3.175 3.250 3.250 0.8 0.035 7311 477 2.50260 3.19926 0.69666 Mean Geometric Mean Harmonic Mean 2.88086 2.87660 2.87234 Variance Standard Deviation Skewness Kurtosis Median Mode 6.2. 1. 3_29-2 2. 3_29A-4 LITH.VSH_GR (V/V) Well Legend: 3_29-2 3_29A-4 0.02444 0.15634 -0.03456 1.63642 2.89515 2.67200 Validation The core descriptions included a number of facies, but on inspection these turned out to be either sand or shale. The core description was coded and loaded to Geolog. A visual comparison with core description indicated that sand/shale in the core description was matching the sand/shale log. In addition, sand thicknesses were computed for the cored reservoir zones and compared to the log-derived sand. Results are as tabulated below (Table 6.1). In order to put the differences in perspective, the changes to gas initially in place (GIIP) are indicated. Table 6.1. Comparison of Core vs Log Defined Sands Well & Interval 3/29-2: UMR2 3/29a-4: UMR1L UMR2 UMR3 LMR Gross Interval, m Core Sand Count, m Log Sand Count, m Interval GIIP, bcf Percentage Change in GIIP, % 15 8 9 92 + 1.0 28 21 13 29 20 5 11 22 17 2 11 20 630 92 169 284 - 8.0 - 4.7 0 - 2.2 Page 25 0.00 Possible values Missing values Minimum value Maximum value Range 0.10 3.28 3.20 3.12 3.04 Wells: 1.00 Statistics: 2.96 2.88 2.80 2.72 0.0 2.64 0.1 0.000 2.56 0.005 0.20 0.2 0.30 0.010 0.40 0.3 0.50 0.015 0.60 0.4 0.70 0.5 0.020 0.80 0.6 0.90 2.8 g/cc cut off 0.025 LITH.RHO_MAA (G/C3) 0.7 0.030 0 LITH.RHO_MAA vs. LITH.VSH_GR Crossplot Frequency Histogram of LOG_LITH.RHO_MAA_1 Well: 3_29-2 3_29A-4 Intervals: KCF, UR, INTER RES SHALE, IRS, UMR1, UMR2, UMR3, LMR, LR Filter:
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Core and log-derived lithologies are displayed on Enclosures 1 and 3. A reasonable match was seen in all cored zones except for the UMR2 in 3/29a – 4. The core to log match is proportional to sand bed thickness. UMR3 is predominantly sandy with beds 0.5m to several metres thick. UMR1L and LMR are thinly interbedded sand and shale zones, with sand beds thicker than 25 cm to greater than 1m. The UMR2 in 3/29 – 2 has 80 percent of sand beds thicker than 10 cm, with most beds 15cm to 20cm. Within the shales there are very thin (<1cm) sands that will not be seen by the logs. The density log in 3/29 – 4 UMR2 fails to resolve the very thin sand beds (predominantly less than 10 cm thick in core) and sees predominantly shale (Figure 6.7). On Figure 6.7 the core sand grain density in track 3 matches RHO_MAA in sand beds in the zones above and below UMR2. However in UMR2 the RHO_MAA consistently indicates shale and does not meet any of the sand grain density points except in the thickest bed. Note that the neutron/density curves in track 2 only show crossover at the thickest bed. Tracks 6 and 7 illustrate the log and core derived sand/shale flag. The thicker black lines in track 7 are thin sands in the core that are below display resolution. For interbedded UMR1L and UMR3 zones and UMR2 in 3/29 – 2, an error bar of +/-15% may be appropriate. However, some of this error will be caused by the difficulty of exactly depth-matching core to log in thinly interbedded units as well as log resolution issues. In sandy units (UMR3) the lithology flag works very well. The main reservoir in Rhum is the UMR1L and UMR3. The lithology flag will not indicate sand where bed thickness is less than 10 cm. In order to refine the sand/shale log further, over cored intervals the core sand/shale description was overwritten in the sand/shale log. In 3/29 – 2 this is the UMR2 description and in 3/29a – 4 this is the UMR1L, UMR2, UMR3 and lower part of the LMR (50% of the entire reservoir interval). This effectively solves the problem of log resolution in the UMR2 zone since this is the only reservoir zone with sand beds below log resolution. Core lithology descriptions are stored in Geolog as CORE_LITH.CORE_LITH. Log-derived lithology is stored as LOG_LITH.LOG_LITH. Figure 6.7. 3/29a – 4 UMR2 Zone Log Resolution 1 2 3 4 5 Page 26 6 7
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 7. PERMEABILITY ANALYSIS Descriptions of available core analysis data are included in the Appendices (Appendix 2 and 3). It is recommended that these Appendices are read carefully before using core-derived permeability data stored in Geolog because the data are of variable quality. Permeability data in 3/29 – 2 are Klinkenberg-corrected air values. In 3/29a – 4 permeability data are fully corrected for reservoir conditions, using the equation: Kreservoir = Kklinkenberg * ((deviatoric stress/test pressure) ^ (-0.1294 + 0.02028 * LnKklinkenburg)) The ‘best’ set of permeability GASPERMS.K_GAS_CORR. data in Geolog for 3/29a – 4 is in the set Core poroperm cross plots are included (Figure 7.1 and 7.2). Poroperm transforms are: Well 3/29 – 2 3/29a – 4 Transform K, mD = 10**(-2.13677 + 27.6912*(PHIE)) K, mD = 10**(-1.97738 + 29.0513*(PHIE)) PHIE is a decimal. The transforms quoted above are adequate for permeability log generation, but the 3/29a – 4 transform gave anomalously high value spikes in places. A multiple regression transform was substituted for the simple regression in order to remove the anomalies. The regression equation is: K, mD = 10**(-7.08097 + 0.0538037DT + 0.00299236RT + 0.310255PE + 21.1147PHIE). This relationship gave a fit to core data similar to the simple transform (Figure 7.3). For the IRMS model input a maximum upper limit of 1500 mD was applied to the permeability logs (maximum permeability in core was 1300 mD). All shale values were set to 0.0001 mD. Page 27
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 7.1. 3/29 – 2 Poroperm Relationship 0 0.300 0.270 0.240 0.210 0.180 0.150 0.120 0.090 0.060 0.030 0.000 Well: 3_29-2 4508.0 - 4688.5 METRES Filter: 0 33 35 2 0.300 0.270 0.240 0.1 0.210 1 0.180 1 0.150 10 0.120 10 0.090 100 0.060 100 0.030 1000 0.000 10000 1000 CORE.CKHL_2 (MD) 10000 0 CORE.CKHL_2 vs. CORE.CPOR_OBC_1 Crossplot 0.1 Poroperm Transform: Kh, mD = 10**(-2.13677 + 27.6912* PHIE) - porosity is a decimal Note: This was used to generate permeabilities in this well only. CORE.CPOR_OBC_1 (V/V) Functions: coreporoperm : Regression Logs: CORE.CPOR_OBC_1, CORE.CKHL_2, CC: 0.903804 y = 10**(-2.13677 + 27.6912*(x)) Page 28
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 7.2. 3/29a – 4 Poroperm Relationship 20.0 18.0 16.0 14.0 12.0 10.0 8.0 6.0 4.0 2.0 0.0 0 Well: 3_29A-4 4633.5 - 4894.0 METRES Filter: 0 107 123 16 1000 100 100 GASPERMS.K_GAS_CORR_1 (V/V) 1000 0 ASPERMS.K_GAS_CORR_1 vs. CORE.COREPHIH1_OBC_1 Crossplot Poroperm Transform: 10 10 1 1 20.0 18.0 16.0 14.0 12.0 10.0 8.0 6.0 0.01 4.0 0.01 2.0 0.1 0.0 0.1 CORE.COREPHIH1_OBC_1 () Functions: poroperm : Regression Logs: CORE.COREPHIH1_OBC_1, GASPERMS.K_GAS_CORR_1 0.802344 y = 10**(-1.97738 + 0.290513*(x)) Kh, mD = 10**(-1.97738 + 0.290513* PHIE) - porosity in % Note: This relationship was not used to generate permeabilities in the IRMS model. Instead a multiple regression was made, fitting core data to a suite of log curves. Page 29
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 7.3. 3/29a – 4 Log Permeability Compared with Core Permeability 10000 1000 100 10 1 0.1 0.01 6 Well: 3_29A-4 4630.5 - 4897.0 METRES Filter: 0 114 133 13 10000 1000 1000 100 100 10 10 1 1 CORE.COREKH1_1 () 10000 0 CORE.COREKH1_1 vs. CALC.K_LOG_1 Crossplot 10000 1000 100 10 1 0.01 0.1 0.01 Kh, mD = 10**(-7.08097 + 0.0538037DT + 0.00299236RT + 0.310255PE + 21.1147PHIE) 0.1 0.01 0.1 Poroperm Transform: CALC.K_LOG_1 (MD) Functions: test : Regression Logs: CALC.K_LOG_1, CORE.COREKH1_1, CC: 0.818829 y = 10**(-0.0074497 + 0.955859*log10(x)) Page 30
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 8. PRESSURE ANALYSIS AND FREE WATER LEVEL Valid RFT, RCI and FMT pressure points are tabulated below (Table 7.1). Table 8.1. Rhum Formation Pressure Data Formation KCF UR UMR1 UMR3 LMR LR Devonian Devonian MD, m 3/29 – 2 TVDSS, m RFT, psi MD, m 3/29a – 4 TVDSS, m 4539.0 4565.0 4852.0 4862.0 4515.5 4541.5 4828.0 4838.0 12296.00 12281.00 12456.00 13493.00 4633.5 4666.7 4692.0 4760.0 4773.0 4834.0 - 4605.5 4638.9 4664.8 4732.8 4806.3 4854.2 - FMT or RCI, psi 12353.92 12369.26 12381.16 12412.40 12500.00 13300.00 - The pressure data in 3/29a – 4 are plotted on the attached figure (Figure 8.1). A gas gradient of 0.151 psi/ft can be defined. Forcing a water gradient of 0.433 psi/ft through the uppermost FMT Run 1 pressure point in the LMR gives a water and gas gradient intercept at 4745m TVDSS, defining the free water level (FWL). The FWL is the elevation of the gas-water contact free of capillary effects, i.e. the level of the fluid contact in a very wide borehole. It can be defined as the depth in the reservoir where the pressure in the gas phase is equal to the pressure in the water phase. In the reservoir, the fluid contact as indicated by electric logs (the gas-water contact or GWC) may be shallower because of capillary effects in the reservoir rock giving higher water saturations above the free water level. On test, free water will not be produced above the FWL. Gas gradients of 0.145 psi/ft were computed from PVT analysis of gas density and 0.139 psi/ft from the difference between downhole gauge and wellhead pressure. In 3/29 –2 a gas gradient of 0.17 psi/ft can be fitted to three FIT pressure points in the gas leg (Figure 8.2). This figure also illustrates the rapid pressure increase in the water leg with depth (Watts, 2002). Both the reservoir and surrounding formations are overpressured. Overpressure in the envelope formations is higher than in the reservoir, with estimated gradients as high as 0.85 psi/ft. In 3/29-2 there is gas-down-to (GDT) base reservoir, at 4689mBRT or 4651mTVDSS. Note the TVDSS in the well evaluation report (4664m) is wrong and assumes a vertical well. The relative position of the reservoir and FWL in the two Rhum wells is illustrated by Figure 8.3. Modelling of direct core water saturation data gave a FWL of 4744mTVDSS, in very close agreement with the formation pressure data (Mitchell, 2001). Hydrocarbon shows while drilling 3/29a – 4 were generally poor and do not help in defining the FWL (Watts, 2001). Page 31
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 8.1. 3/29a – 4: RCI and FMT Formation Pressure Plot 3/29a-4 Formation Pressure Plot (All Runs) 4660.0 4680.0 4700.0 UMR 1 Gas gradient 0.151 psi/ft or 0.411 gm /cc fit through FM run1 points UM and UM T R1 R3 4720.0 UMR 3 Depth (m tvdlat) 4740.0 Contact 4745.1m TVDSS 4773.1m MD 4760.0 LMR 4780.0 Water gradient set at 0.433 psi/ft T R Forced through FM run1 point in LM 4800.0 4820.0 LR 4840.0 FM run 1 T RCI run 1 RCI run 2 RCI run 3 FM run 2 T FM run 3 T RCI 4&5 Data Gas Gradient Water Gradient LR 4860.0 12300.0 12400.0 12500.0 12600.0 12700.0 12800.0 12900.0 13000.0 13100.0 13200.0 13300.0 Formation Pressure (psi) Page 32
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 8.2. Rhum Field Formation Pressure Plot Rhum Field Formation Pressure Plot 4480.0 RFT (3_29-2) FIT (3_29-2) 4530.0 FMT 1(3_29a- 4) RCI 1 ( 3_29a-4) RCI 2 ( 3_29a-4) 4580.0 RCI 3 ( 3_29a-4) 0.172 psi/ft (~Gas Gradie nt ) FMT 2 (3_29a-4) 4630.0 D epth (m tvdss) FMT 3 (3_29a-4) RCI 4 ( 3_29a-4) Regional Pressur e Gradient 4680.0 Water Gradient 4730.0 Linear ( FIT (3_29-2)) Re gional Pres s ure Gradient 1.92 s g FWL @ 4745 Break depth to "proper" over-pressur e trend in "aquifer" = "regional" pressure ? 4780.0 4830.0 Wat er Gradie nt 4880.0 12100.0 4930.0 12300.0 12500.0 Over-pressur e aquifer trend (or return to regional "overpressure") ? 12700.0 12900.0 13100.0 13300.0 Formation Pressure (psi) Page 33 13500.0 13700.0 13900.0 14100.0
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 Figure 8.3. Well Corellation in True Vertical Depth Indicating FWL Position in Reservoir CALC.BVW_1 1 1 GR 0 GAPI 250 0 V/V CALC.PHIE_1 0 LITHOLOGY METRES TVDSS Zone Reservoir 3/29-2 V/V 0 CALC.VSH_GR_1 V/V 1 4470 4476 4475 4480 4485 KCF 32 4490 4495 4500 4508 4505 UR 4511 4510 4515 IRS 20 4520 4525 4532 4530 4535 4540 3/29A-4 UMR1 29 4545 4550 4555 4561 4560 CALC.BVW_1 1 1 GR 0 GAPI 250 0 V/V CALC.PHIE_1 0 V/V 0 CALC.VSH_GR_2 V/V 1 LITHOLOGY TVDSS METRES Zone Reservoir 4565 UMR2 19 4575 4585 UMR3 21 4600 4595 4610 4615 4615 33 4620 4620 4625 4630 LMR 50 4625 4630 4635 4635 UR 4590 4601 4600 4605 4606 4605 4610 KCF 4570 4580 4580 4639 4640 4640 4645 IRS IRS 25 4645 4650 4651 4650 4655 4655 4660 4665 4665 UMR1U UMR1U 18 4683 22 4670 4675 4680 4665 4673 HEATHER 10 GDT 4651 m in 3/29-2 4660 LR 4670 4675 4680 4685 4690 UMR1L UMR1L 27 4695 4700 4705 4710 4710 4715 UMR2 UMR2 22 UMR3 4720 4725 4732 UMR3 13 4730 4735 4740 4745 4745 GWC 4745 m in 3/29a-4 4750 4755 4760 4765 4770 LMR LMR 61 4775 4780 4785 4790 4795 4800 4806 4805 4810 4815 4820 4825 LR 4830 LR 4835 59 4840 4845 4850 4855 4860 4866 4865 Heather 10 4870 Page 34
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 9. SATURATION-HEIGHT FUNCTIONS Water saturation and capillary pressure measurements were made using mercury injection and air-brine porous plate methods on preserved core samples from 3/29a – 4 (Cameron, 2001). Mercury injection data were also available from 3/29 – 2. The sets of data from the two wells were comparable for the same porosity classes. Air-brine measurements were used to determine saturation-height functions for a set of porosity classes (Cameron, 2001). The derived functions are listed in Table 9.1. Table 9.1. Saturation-Height Functions Derived from Air-brine Capillary Pressure Measurements. Rock Type All rock types Φ >10% Φ =8-10% Φ =6-8% Φ <6% Saturation-Height Function Sw = 0.451703*H-0.233628 Sw = (0.2102*H-0.1518)-0.00481 Sw = (0.4169*H-0.2004)-0.00812 Sw = (1.1992*H-0.3407)-0.0302 Sw = (1.367*H-0.1507)-0.00159 The All Rock Types function was used in the non-faulted geological grid RMS model to compute water saturation. The four porosity (Φ) class functions were used in the faulted geological and simulation RMS models (Southwood, 2001). Irreducible Sw, Swi, was estimated to have a most likely value of 0.14 v/v and a potential upside of 0.10 v/v. The ‘H’ term is height in metres above the FWL. In addition to the functions used in the RMS model, ICCS (2001) subsequently computed single saturation – height functions from the same dataset, incorporating Klinkenberg permeability (K) and porosity (Φ) into the saturation – height term: Sw = 0.943*H – 0.234 * K – 0.265 Sw = 0.0121*H – 0.167 * Φ – 1.37 Since the permeability and porosity term is in-built in these equations they should better describe water saturation than the terms listed in Table 9.1. The various saturation – height curves are plotted on Figure 9.1. This displays the four porosity class functions in brown, blue, green and red. The all rock types curve is plotted in pink. This overlies the 8 – 10% porosity class curve. Average overall reservoir porosity is 7% (see Section 10), so it is reasonable that these curves overlie. The green dashed line is the ICCS (2001) curve for a 7% porosity case, and lies between the 6 to 8% and 8 to 10% Cameron curves. The ICCS equation and the all rock types equation were input to Geolog and used to compute SW. The results are displayed on the CPIs (Enclosures 1 and 3). For 3/29a – 4 (Enclosure 1) track 14 on the CPI displays log-derived SW (MRIL_SW from the MRIL tool, SWE from the HDIL and SWE_3DEX from the 3DEX). Curves are compared with core direct SW (COREICSW1). The MRIL_SW and COREICSW1 data show the lowest SW. In fact COREICSW1 data appear to be unreasonably low. Note that both these datasets are only good above the FWL (see Mitchell, 2001 for discussion of data quality). In track 15 on the CPI the COREICSW1 data are compared with two of the model curves: SW_MODEL_ICCS is computed from the ICCS (2001) porosity/height/SW equation; SW_MODEL_CAMER is computed from the Cameron (2001) all rock types equation. Note that the all rock types equation does not have a porosity term and is thus a smooth curve on the log. The two model curves show reasonable agreement and also agree with the 3DEX and HDIL-derived SW curves. The agreement of model data with log data is reassuring, but the reasons for very low core SW data should be investigated further. In 3/29 – 2 (Enclosure 3, track 12) the model SW curves give considerably lower SW values than the log SWE curve (whether derived from Page 35
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 the LLD or ILD resistivity data). There are no core saturation data available. The discrepancy should be investigated further – it may be that the resistivity log data require environmental correction or else the SW/height equations should be modified, since in this well the SW/height equations give very low SW values in the gas leg. Figure 9.1. 3/29a – 4 Sw – Height Functions Sw-height function (by porosity classes) 120 110 Height (m) above FWL 100 90 80 70 60 50 40 30 20 10 0 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 Sw (frac) Phi >10% Sw = 0.2102*(H^-0.1518))-0.00481 Phi 6-8% Sw = (1.1992*(H^-0.3407))-0.0302 Core Data Phi 7% Sw = (0.0121*(H^-0.167)*(0.07^-1.37)) Phi 8-10% Sw = (0.4169*(H^-0.2004))-0.00812 Phi < 6% Sw = (1.367*(H^-0.1507))-0.00159 All rock types Sw = (0.451703*(H^-0.233628)) Page 36 1
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 10. ZONE AVERAGES Reservoir zone averages are computed using the binary lithology flag LOG_LITH.LOG_LITH_BIN as the net flag. All sand beds are included as net. Averages are tabulated below (Tables 10.1 and 10.2). Table 10.1. 3/29-2 Reservoir Properties 3/29 – 2 Reservoir Properties Zone Zone Top, m Zone Top, mTVDSS Gross, m Net, m NTG, % Porosity, % Arith. Perm., mD Geom. Perm., mD UR 4540 4507 3.4 3.4 100 16.4 669 255 UMR1 4565 4532 29.2 28.0 96 11.2 250 9 UMR2 4595 4561 19.4 12.7 65 11.4 85 11 UMR3 4615 4580 20.9 19.1 91 7.4 14 1 LMR 4636.5 4601 50.5 44.4 88 2.8 4 0.1 123.4 107.6 87 7.0 100 12 Totals Note: entire reservoir in gas leg Table 10.2. 3/29a-4 Reservoir Properties 3/29a – 4 Reservoir Properties Zone Zone Top, m Zone Top, mTVDSS Gross, m Net, m NTG, % Porosity, % Arith. Perm., mD Geom. Perm., mD UR 4666.5 4639 1.0 0.5 50 0.5 0.2 0.1 UMR1U 4692.5 4665 17.9 0.7 4 3.8 3 0.4 UMR1L 4710 4683 26.8 17.9 67 9.2 70 12 UMR2 4737.5 4710 22.3 5.0 22 6.9 1 0.5 UMR3 4760 4732 12.9 10.4 81 6.8 18 1 LMR 4773 4745 61.0 45.1 74 6.4 4 0.2 15.4 32 7.1 1.3 0.2 95 50 6.8 17 2.5 35 43 7.3 42 6.6 60 55 6.6 3.3 0.2 LR 4834.5 4806 47.6 Totals – all 189.5 zones Totals – 81 gas leg Totals – water 108.5 leg Note: gas leg extends from UR to base UMR3. Page 37
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 11. RHUM ROCK PROPERTIES A rock properties study was conducted to: • • • • Investigate the feasibility of using a lithological impedance (LI) cube to discriminate between sand and shale. Determine how consistent the sand and shale properties are in offset wells. Determine whether lithology impedance can be used to map variations in reservoir quality and hence the distribution of the UMR and the LMR. Determine whether the gas/water contact is seismically detectable. The rock properties study is documented in Keir (2001). The study concluded: • The application of LI maps to discriminate between the UMR and LMR sands and the overlying shales is possible but depends very much on the reservoir architecture being similar to that of the 3/29a – 4 well. If the reservoir more closely resembles that encountered in the 3/29 – 2 well or the properties of the underlying shales are similar to those encountered in the 3/29 – 2 well, then application of LI will most probably not allow discrimination between sands and shales. • The differentiation of reservoir quality (porosity) is more problematic and probably not possible. • The properties of the shales are reasonably consistent in the offset wells, with the exception of the 3/29 – 2 well. • Where porosity is high enough (above 10 – 12 PU) the difference between brine-filled sands and gas-filled sands should be detectable with changes in acoustic impedance and fluid impedance. • The dataset used in the modeling study is of varying vintages, quality and instrument technology. Whilst the data has been verified as meeting the QC standards as set by the logging contractors, a systematic error could exist which may influence the observed differences in rock properties across the field. Page 38
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 12. CONCLUSIONS AND RECOMMENDATIONS The Rhum Field gas accumulation was discovered by the 3/29 – 2 well in 1977. Core indicated that the reservoir was a thinly-bedded turbidite sequence. In order to resolve and quantify reservoir quality in such a thinly-bedded sequence, a comprehensive suite of log data was acquired in the subsequent appraisal well 3/29a – 4. The selected logging program was largely successful and did improve thin sand definition. It is important to have a range of logging tools to address separate but related aspects of reservoir quality. Thus the best tool for determining gas saturation and sand volume overall was the MRIL, while individual thin bed quality was best measured by high-resolution density logs and the 3DEX tensor resistivity tool. However, the 3DEX data cannot be interpreted in-house and it is important to involve the logging company in job planning, execution and interpretation. It was difficult to get a definitive measure of water saturation from log and core data. Core saturation data in 3/29a – 4 indicated very low water saturations in the gas leg. Although the direct core saturation data agreed with the MRIL saturations, all other data (log SW and capillary pressure data) indicated higher water saturations in the gas leg. Core saturation data should be reviewed. The importance of good core data cannot be overstated and some reservoir features would have gone unnoticed if core had not been available. For example, special core analysis of 3/29a – 4 core provided refined Archie parameter values, porosity and permeability data corrected for reservoir pressure and overburden, confirmation of formation water resistivity and saturation-height data. Very thin, cm-scale, sand beds were seen in core that are not detectable on logs but are likely to contribute to production. Given the resolution limitations, it may be preferable to perforate the entire gas-bearing zone, from top KCF down to the FWL. Anomalously high porosities and, consequently, gas saturations, were computed from the density log in the LR Zone in a zone that did not flow on test. The MRIL log indicated much lower porosity in the same zone. The most likely explanation for the difference is that grain densities in the LR are lower than typically encountered higher in the reservoir. Some low grain density data points were measured in core plugs in the overlying LMR. However, petrography studies failed to identify the nature of the low density material. Core plugs should be reexamined in order to rectify this. It would also be worthwhile in future wells to get core over the LR to establish if low grain density material exists in this zone also, so that the porosity model over the LMR and LR can be refined. Reliable pressure data were obtained that define gas and water gradients and a FWL at 4745mTVDSS. The FWL indicated by formation pressure and core data data is consistent with the log data. Given the HPHT nature of the gas volume, even low permeability sands are likely to contribute to production. Net sand is therefore defined as equivalent to gross sand. Extensive core indicates that the reservoir is either fine to medium-grained sand or shale and a simple sand flag was devised to describe net, based on matrix density and shale volume. Rhum Sand reservoir quality is variable, being generally moderate but ranging from poor to good. The highest porosity and permeability was seen in the UR zone of 3/29 – 2, with 100% NTG averaging 16.4 PU and 255 mD (zonal averages) in a 3.4m thick sand, but the same sand in 3/29a – 4 is only 1m thick with 50% NTG, less than 1 PU and 0.1 mD. The UMR zone ranges in porosity between 3.8 and 11.4 PU, permeability 0.5 to 12 mD and NTG 4 to 96%. Individual beds in the UMR exhibit Darcy-scale permeability. Despite the variability between reservoir zones, the total net reservoir thickness is similar in both wells, being 108m in 3/29 – 2 and 95m in 3/29a – 4. All sand was counted as net, using cutoffs of VSH<0.4 and RHO_MAA<2.8 g/cc. 3/29 – 2 penetrated deeper Jurassic (Heather) and Devonian sand sequences, but these were water-bearing and tight. Thus no significant reservoir intervals could be seen on the logs below base Rhum Sand. Page 39
  • Rhum Petrophysical Reservoir Evaluation: v1.0 13/08/2005 13. REFERENCES Baird, T., Fields, T., Drummond, R., Mathison, D., Langseth, B., Martin, A., Silipigno, L. 1998. High-Pressure, High-Temperature Well Logging, Perforating and Testing. Oilfield Review, Summer 1998. Cameron, N. 2001. Rhum Saturation – Height Modelling. Technical File note. Doveton, J.H., 1994: Geologic Log Analysis Using Computer Methods. Applications in Geology, No. 2. AAPG Computer ICCS, 2001. Petrophysical SCAL Study: Well 3/29a – 4 (Rhum). Phil Mitchell, Integrated Core Consultancy Services Limited (ICCS). Keir, D. 2001. Rhum Rock Properties. BP, Upstream Technology Group, July 2001. McBride, J.J. and Cook, G.E. 2001. Strontium Isotope Residual Salt Analysis (SrRSA) and Chemical and Isotope Analysis of DST Waters from Well 3/29a – 4. IAS Limited, May 2001. Mitchell, P. 2001. Direct Water Saturation from Core Study: Well 3/29a – 4. ICCS March 2001. Page, G. 2001. Rhum Field. GEOScience. August 2001. Well 3/29a – 4. Petrophysical Analysis. Baker Atlas Paintal, G. 2002. A Petrographical, Reservoir Quality and Fluid Inclusion Characterisation of Well 3/29a – 4, and a Quick-Look Petrographical Review and Fluid Inclusion Study of Well 3/29 – 2, Rhum Field, UKCS. Gautam Paintal, Badley Ashton & Associates Ltd. March 2002. Southwood, D. 2001. Rhum Field 3D Geological Modelling and Volumetric Sensitivities. ROXAR. October 2001. Teeuw, D. 1971. Prediction of Formation Compaction from Laboratory Compressibility Data. SPE 2973/SPE Transactions vol 251 September 1971. Watts, T. 2001. 3/29a – 4 End of Well Geological Operations Report. BP April 2001. Watts, T. 2002. Statement of Requirement - Rhum Development Xmas Tree Rating - Sub surface pressures. Whitehead, F. 2001. Petrophysical Analysis of Rhum 3/29a – 4. Limited. February 2001. Page 40 Production Geoscience